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TOTAL Returns to the Cape of Storms in Q1 2020

French major TOTAL will be returning, within the next one year, for further exploration and appraisal of the prospects in South Africa’s Block 11B/12B offshore South Africa, where it discovered large gas condensate pools in January 2019.

The Paris headquartered company has secured the Deepsea Stavanger for a multi-well drilling programme, beginning with the spud of the Luiperd Prospect in Q1-2020. This was the same equipment and crew that drilled the Brulpadda oil and gas discovery.  Up to three exploration wells are expected to be drilled during the forthcoming campaign.

Block 11B/12B is located in the Outeniqua Basin, located 175 kilometers off the southern coast of South Africa. The block covers an area of 19,000 square kilometers with water depths ranging from 200 to 1,800 meters. The Paddavissie Fairway in the southwest corner of the block includes the Brulpadda discovery and several submarine fan prospects.

The success at both the Brulpadda primary and secondary targets significantly de-risks the other similar prospects identified on 2D seismic.  The joint venture partnership for Block 11B/12B recently completed the first phase of the 3D seismic acquisition program over the Paddavissie Fairway.  The Brulpadda well results will be integrated with the three dimensional (3D) seismic data in advance of next year’s drilling programme.

TOTAL operates Block 11B/12B with 45% interest while Qatar Petroleum and Canadian Natural Resources Limited have 25% and 20% interests, respectively. Main Street 1549 Proprietary Limited holds a 10% participating interest.


Will the Drilling Industry Experience A Golden Revival?

By Gerard Kreeft

Imagine a somewhat scranny polar bear in search of his iceberg …all he can find is  barren tundra…he knows with his instincts that it was here somewhere but it is gone… is this also the case of our drilling contractor..  will he again find his iceberg?

Could the drilling industry experience a golden revival?

It is estimated  that total free cashflow for all public E & P companies, in 2018, was $325Billion  (Rystad UCube, July 2018).  A sharp contrast with the approximate $30Billion recorded in 2015. Which drillers will be in a prime position to perform the required drilling services?

At first glance the landscape is a checkered one: in the past three years companies have  reduced their dividends, are in various stages of being  in chapter 11, and still others have been taken over or merged. Yet a further glance indicates that two companies—Transocean and Ensco—are in pole position to become the sector’s dominant players: Transocean because of it’s persistent and diligent effort to position itself in the lucrative ultra-deep and harsh weather market; Ensco because of it’s merger with Rowan to become the dominant player in the jack-up market.  Two important players to watch in the current exploration market.

The Transocean strategy has been long in coming. The basic Transocean company was formed by merging  Sedco-Forex, and Sonat Drilling (prior to that Sonat Drilling had taken over the Norwegian Transocean company and its name). Along the way Global Marine/ Santa Fe and a host of other companies were taken over by the new Transocean, thus positioning  itself in the lucrative ultra- deepwater market.

The sector’s  total deepwater fleet consists of 222 rigs. Transocean has 55 harsh environmental, ultra-deep and deepwater and midwater floaters. Their average fleet age is 11 years, and in 2014 it was 21 years. It has  a pipeline of $12.5Billion projects extending to 2028.  Much of its purchasing has been financed by the street and secured to 2024.

The Ensco Rowan merger will give the new combination the largest jack-up fleet in the world: 82 rigs in total, 28 floaters and 54 jack-ups, 38 which are state-of-the art. The merged company has $2.6Billion inventory of projects.

Ensco, founded in 1975, reflects the ebb and flow of the oil market.

With its purchase of Pride International the company gained access to the Brazilian and West African markets. Rowan is symbolic of the US oil industry. A pioneering company which  established an airline, oil company, and innovative rig technology. The Gorilla Class jack-ups were larger and capable of drilling down to 30 000 feet. The company’s policy of being a close-knit family is legendary.

The Challenge

Dayrates are expected to rise. In 2010 dayrates for drillships/floaters were in the $400 -500 000 range, peaking above $600,000 in 2012-2014. Nose diving to $100,000 -$200,000 in the period 2016-2018. It is anticipated they could rise to $500,000  by 2021.

In June 2014 Transocean’s share price was $45. By December 2018 it was $7. Ensco’s shares suffered a similar fate: in June 2014 a share stood at $55 and in December 2018 it was down to $4. Rowan is no exception: June 2014 the share stood at $32,50, and in December 2018 it was below $9.

According to one industry source the oil companies are  replacing their extracted reserves at a historic low: in 2015 only 25% while the norm should be 100% . Only replacing 1/3 of their offshore production. Can the industry play catchup?

Given the free cash flow recorded in 2018 ($325Billion) can we anticipate that the industry will enhance it’s depleted reserve rate? But perhaps there is something else playing in the background. Everyone assumes that the recorded free cash flow will become the monopoly of the exploration and development budgets! Could this freed up cash also go to renewables?

For the first time in the history of the oil and gas  sector  sector we are witnessing that the sector must compete for funding. According to a recently published divestment report from Arabella Advisors fossil fuels divestments now total an eye-popping $6Trillion, with nearly 1,000 institutional investors having pledged to divest from coal, oil and gas under pressure from environmental groups, governments and increasingly conscientious consumers. This  revealed an increase in divestment from the 2016 figure of $5.2Trillion.

Can the track record of both Shell and ExxonMobil, as shown in this graph, be a litmus test for the future? If Post-Paris is factored in, together with a CO2 and other environmental charges what would the return of investment be? The investment power of renewable energy illustrates that the oil and gas sector must take giant strategic steps if it is to remain a dominant market force. Or are we witnessing a structural downsizing of the sector?

Have drillers  gone through a long-term pain for a short-term gain?  Will the polar bear be able to continue to habitating his iceberg home?

Article was initially published in the March 2019 edition of Africa Oil+Gas Report.

Gerard Kreeft, MA (Carleton University, Ottawa, Ontario, Canada) is a frequent contributor to Africa Oil+Gas Report. He is founder and owner of EnergyWise, a company which has, since 2001, managed and implemented oil and gas conferences, seminars and master classes throughout the world and in Angola on an annual basis.



ENI Will Define Angola’s Near Term Future

Fourth discovery in 18 months

By Sully Manope

ENI’s new light oil discovery in Block 15/06, is the fourth in Angola’s deep offshore in the last 18 months.

Ndungu-1, located a few kilometers from the company’s West Hub facilities, is estimated to contain up to 250Million barrels of light oil in place, with further upside, ENI said in a statement on May 14, 2019.

ENI’s string of discoveries in Angola’s Block 15/06 runs contrary to the trend among the majors in Africa’s second largest oil producer.
TOTAL, the country’s leading producing company and ExxonMobil, the continent’s top oil producer, are not doing so well in the wildcat exploration game in Angola.

TOTAL continues to mine large volumes of crude in the prolific Block 17.

ExxonMobil continues successfully operating the Block 15.

Neither company, however, is topping up their reserves at the pace that ENI is doing. And unlike what appears to be the standard narrative, the activities of these two companies will not significantly define Angola in the next five years, unless they both come up with significant volumes of new finds.
ENI’s Ndungu-1 follows the Agogo-1 discovery, announced in March 2019, with estimates of between 450 and 650 Million barrels of light oil in place, also “with further upside”.

Agogo-1 followed both Afoxe discovery, which was made in December 2018, after the Kalimba-1 discovery, encountered in January 2018, all in Block 15/06.

ENI reports Ndungu-1 to have proved a single oil column of about 65 meters with 45 meters of net pay of high quality oil (35° API) contained in Oligocene sandstones with excellent petrophysical properties. The result of the intensive data collection indicates a production capacity in excess of 10,000 barrels of oil per day. This means that this latest discovery is not as big as Agogo-1.

Agogo-1 proved a single oil column of about 203 meters with 120 meters of net pay of high quality oil (31° API) contained in a sub salt diapirs setting in Lower Miocene sandstones with excellent petrophysical properties, ENI had reported. The data acquired in Agogo-1 NFW indicate a production capacity of more than 20,000 barrels of oil per day.

All these discoveries are the results of the decision by the Block 15/06 Consortium to launch a new exploration campaign in 2018.

ENI acquired the operatorship of Block 15/06 during the bid round of 2006 and Production Sharing Agreement was effective from 1st December 2006. In 2008 the fir st discovery well, Sangos-1, was drilled in about 1,350 m of w ater depth, followed by Cinguvu-1 in 2009 and Mpungi-1 in 2010. In December 2013, the Final Investment Decision was taken for the West Hub project (Sangos, Cinguvu and N’goma and Mpugi fields)
ENI had indicated that Afoxe 1 could add 5,000BOPD, Agogo-1 indicates a putative addition of 20,000BOPD and now Ndungu can add 10,000BOPD, to Block 15/06 output. These estimates are based on data that do not include well tests. ENI has said that this string of discoveries “represent a new cluster that can be exploited jointly in a new development concept”. The continuous improvement in the finds (from Kalimba through Afoxe to Agogo) point to a near term cluster development that could deliver as much as 75,000BOPD.

This is an update of the report of the same title, published in the March/April 2019 edition of the Africa Oil+Gas Report..

Ghana’s Pecan South Sidetrack Was A Duster, But…

Aker Energy says the sidetrack well to its Pecan South appraisal, offshore Ghana was disappointing

The well “encountered oil shows, but no recoverable resources due to a tight reservoir”, the company says in an update. Even then, “based on preliminary data analysis, it is estimated that between 5-15Million barrels of oil equivalent (MMBOE) could be added to the Pecan field development from Pecan South”.

Pecan South is one of the three appraisal wells drilled between November 2018 and April 2019 in the Pecan field and its satellites in the Deepwater Tano Cape Three Points DWT/CTP area. The company is working on fast paced development of the asset, purchased from Hess in February 2018.

Aker says its current estimates of producible volumes the field “exclude any additional volumes from Pecan South and Pecan South East, currently being assessed”.

Fuller details in the May 2019 edition of the Africa Oil+Gas Report.

Aker Energy is the operator under the DWT/CTP Petroleum Agreement with a 50% participating interest. Its partners are Lukoil Overseas Ghana Tano Limited (38%), the Ghana National Petroleum Corporation (GNPC) (10%) and Fueltrade Limited (2%).



Oilserv Chief Says He’ll Break the Jinx in the Benin Basin

Emeka Okwuosa, Chief Executive Officer of Oilserv, says he is undeterred by the news that the Benin Basin, of recent, has been a graveyard of E&P dreams.

“I understand the reservoirs. In 1988/1989, I was the resident Schlumberger manager of West Africa based in Benin Republic and I helped to develop the Seme field. So I understand the reservoir structure there”, he told Africa Oil+Gas Report

Oilserv is mostly a midstream service, EPCI company, with interests in engineering studies, E&P and power distribution. The company’s E&P subsidiary, Frazoil, holds an acreage, Block 3,  in the basin, in Benin Republic, so Okwuosa’s perspective here is that of a licence holder.  “I know why other investors have made mistakes and I know what I am looking for”.

But while Mr.Okwuosa is not a geoscientist, he argues that he understands the risk. “Don’t forget that historically, less than 30% of exploration turns out production so it is never an exact science. In fact, in most places it is less than 17%”.

The facts that Okwuosa is dealing with are stubborn. Conoil drilled an exploration well on the boundary between Benin and Niger Delta Basins in 2018, which failed spectacularly. For a full year, Yinka Folawiyo &Co have been unable to increase production on the Aje field (the only Nigerian producing field located in the Benin Basin) from 3,000BOPD, let alone get anywhere close to the prognosed 10,000BOPD peak. SAPETRO exited its two assets in Benin Republic about two years ago after four unsuccessful wells in the basin.

Optimum/ Lekoil/Afren discovered the Ogo field in OPL 310 in the Benin Basin in 2013, but the jury is out on what the technical/geoscientific experience would be, when the work programme moves into the next phase of appraisal.

“I have an advantage. I also have a strong belief that it will work out well even though it is still a risk”, says Okwuosa.

As to how he would fund the drilling, the oilfield entrepreneur says it is a process. “You know that E&P is different from EPC. We have the whole thing worked out and we are directly funding part of the exploration and today, we funding seismic acquisition, processing and then the interpretation. When we get to a stage where we have to drill or invest more, we can have to farm-out but like I said, it is a process. When we get there, we will cross it”.



First E&P Spuds First Well on Anyala & Madu

First E&P has spud its first well in development of the Anyala and Madu field,s in Oil Mining Leases(OMLs) 83&85, offshore central Niger Delta.

The driller is UAE based Borr Drilling, who will be utilising the Natt, one of its premium jack ups, for the two year contract running from April 2019 to April 2021.

The fields will be drained by 20 wells in total. The agreement to develop Madu and Anyala (discovered by Texaco, which was bought over by Chevron) was signed between Schlumberger, NNPC and First E&P, as far back as June 2017, with Schlumberger committing to provide technical services, as well as funding the $724Million for the project.

First E&P acquired approximately 900km² of 3D seismic data over both licenses between October 2017 and January 2018. Aquaterra Energy was contracted to design, develop and install two offshore platforms for the project, Africa Oil+Gas Report reported in December 2018.

The scope of work includes design, topsides engineering, procurement, fabrication and logistics. The Norwhich, UK headquartered contractor is expected to deploy the Seaswift offshore platform on the two sites. It will work on the project in conjunction with a local partner, Maerlin Nigeria Limited, a relatively unknown, Nigerian owned oil and gas service firm. (On its website, Maerlin does not disclose what projects it had been involved in, in the manner of most Nigerian service companies).

The partners will manage the end-to-end project scope with engineering and onsite fabrication support being performed in Nigeria, Africa Oil+Gas Report reported last December. The platforms were supposed to be installed in water depths of 35metres to 55metres with first oil expected in late 2019, but with the first well just being drilled, the likelihood of first oil in 2019 is far fetched. Yinson Production, a subsidiary of Yinson Holdings, signed a heads of terms agreement with First E&P to supply and charter an FPSO for the project. The Anyala and Madu fields are estimated to contain combined reserves of 193 million barrels of oil (MMBBls) and 0.637 trillion cubic feet (Tcf) of gas.

ENI, Chevron Push Up The Angolan Rig Count

By Toyin Akinosho

Chevron has contracted the rig  Sapura Jaya from Sapura Energy. It is expected to be on location offshore Angola in April.

With this, the American oil major joins the Italian explorer ENI, in pushing up the Angolan Rig Count.

ENI deployed Seadrill’s West Gemini in February 2019, shooting the rig count in the country by…

It’s a small indication that recovery is on the way, even though a rig count of 7 is still a long distance  from the 22 back in 2014/15.

Eroton Finalises Akaso-15, Moves onto Next Well

Nigerian minnow Eroton, is currently finalising the first well it would drill as an operator and has moved the rig to the second well in the campaign.

The operator of the Oil Mining Lease (OML) 18 licence, in Nigeria’s eastern onshore Nigeria, has completed Akaso 15 and has progressed significantly in connecting the well to the pipeline system. Akaso-15 is expected to be brought onto production during the first half of March 2019, and a well test will be performed once the well has achieved stable production.

Akaso-15 was prognosed to reach Total Depth around 11,900 ftMDBRT (measured depth below rotary table), targeting the E4500 and E3000 formations. The well was drilled with the Sheng Li 4 rig, which was in action for Newcross on Awoba NW 2 (OML 24) in the neighbourhood.

Eroton purchased 45% of OML 18 from Shell, TOTAL and ENI in 2015, and acquired the operatorship along with the purchase, in joint venture with the NNPC, which owns 55%. It has kept the output at around 40,000BOPD with work overs and field optimisation, but it had not drilled any new wells until now.

The next well is called Akaso PMMO-1.


Nigeria’s Oil Finders Look for Pay Dirt outside The Niger Delta

Nigeria’s Petroleum Explorationists have decided to formalise the search for oil and gas accumulations outside the Niger Delta.

They have come together to organise a workshop, to collate the most current thinking on geological basins outside the Delta basin.

The Niger Delta basin hosts all of the oil accumulations being produced in Nigeria, with the exception of one; the Aje field, offshore Lagos, which produces a minuscule volume: 3,000Barrels a day, or 0.15% of the country’s entire output.

Aje field lies in the Benin Basin, which was laid down in the Cretaceous period, a geological age preceding the Cenozoic period, during which the Niger Delta was laid.

It so happens that the other sedimentary basins in Nigeria: Benue Trough, Chad Basin, Sokoto Basin etc, were, like the Benin Basin, all laid down during the Cretaceous.

The crude oil finds around West Africa in the last 15 years, including Ghana’s Jubilee, Senegal’s SNE, and discoveries in Niger Republic and Gabon, are all in basins of cretaceous age.

This is why the organisers of the workshop have christened their proposed parley the Cretaceous In Nigeria Workshop. It is two day affair, organised under the auspices of the Nigeria Association of Petroleum Explorationists (NAPE), and is to be held in Abuja from May 6 to May 7, 2019. It is to “be a forum for harnessing and sharing the knowledge of Cretaceous geoscience, in order to develop sound technical understanding of the different Petroleum systems supported by proven global analogs, says Muyiwa Olawoki, Ph.D, a retired ranking geoscientist with careers in Shell and ExxonMobil under his belt, who is currently running his own  consulting firm, Geospectra Limited.

Some of the usual suspects, without who this workshop would not happen, are Ebi Omatsola, Joe Ejedawe and Kehinde Ladipo. They are all PhDs and they have been pushing the idea of an industry/government collaboration in interrogating the Cretaceous data set in Nigeria for a while. Omatsola is former Chief Geologist at Shell and founding Managing Director of Conoil Producing. He is Africa’s leading exploration thinker and former President of the Nigerian Association of Petroleum Explorationists (NAPE). Ejedawe and Ladipo are both industry icons; who started out in academia and later spent more than 15 years in Shell each. Ejedawe received NAPE’s highest award, the Aret Adams’ Award, in 2017. Ladipo set up a Post Graduate Geocience School in the University of Benin after he retired from Shell.

“Representatives from government agencies, local and international oil companies, and the academia are expected to attend”, says Olawoki, who is the convener.

Although exploration in the country started in basins of cretaceous age, Oil majors operating in Nigeria have progressively stopped being interested in basins outside the Niger Delta, since Shell discovered Oloibiri in Bayelsa State 63 years ago. The narrative, since discovery, with the exception of TOTAL’s foray into the Benue Trough, has been almost entirely about the Cenozoic Niger Delta. It is the NNPC, the state hydrocarbon company, which has been most enthusiastic about the Cretaceous play.

The word “Cretaceous” probably needs to be explained for our readers not familiar with geological terms. Cretaceous refers to that era, in the geologic definition which started 145Million years ago and ended 66Million years ago, lasting 79 Million years. What is important for oil finders is that it with a relatively warm climate, resulting in high eustatic sea levels that created numerous shallow inland seas. These oceans and seas were populated with marine reptiles (now extinct) ammonites and rudiststs. The end of the Cretaceous era is marked by the extinction of the Dinosaurs.

The May 7-9 workshop will discuss, among others:  Global Rift Setting Overview and Analogs; Pre-Cambrian Basement Impact on the Evolution of the Cretaceous Basins; Geophysics and Basin Architecture; Stratigraphy and Depositional Systems; Geochemistry and Basin Modelling and Exploration Activities.



TOTAL Makes “Significant” Condensate Discovery offshore South Africa

French major TOTAL has described, as significant, its gas condensate discovery on the Brulpadda prospects, located on Block 11B/12B in the Outeniqua Basin, 175 kilometres off the southern coast of South Africa.

The Brulpadda well encountered 57 metres of net gas condensate pay in Lower Cretaceous reservoirs. Following the success of the main objective, the well was deepened to a final depth of 3,633 meters and has also been successful in the Brulpadda-deep prospect, the company said.

Kevin McLachlan, TOTAL’s Senior Vice President Exploration, said the French major had “opened a new world-class gas and oil play” with this well, “and is well positioned to test several follow-on prospects on the same block.

Mr. McLachlan’s talk of several follow up prospects, is echoed by an enthusiastic statement by Africa Energy, one of TOTAL’s smaller partners on the lease. “The success at both the Brulpadda primary and secondary targets significantly de-risks four other similar prospects already identified on the existing 2D seismic. The Block 11B/12B partners plan to acquire 3D seismic this year, followed by up to four exploration wells”.

The Brulpadda well was drilled in approximately 1,400 metres of water by the Odfjell Deepsea Stavanger semi-submersible rig. The two primary objectives were in in a deep marine fan sandstone system within combined stratigraphic/structural closure and was deepened after successfully testing those objectives. Core samples were taken in the upper reservoir, and a comprehensive logging and sampling program was performed over both reservoirs.

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